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COMPUTALOG DRILLING SERVICES

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Operations Manual OPDD _140_revA_0304

Computalog Drilling Services !6172. \fVes: HS"CY Roac HcGsto:: Texas 77060 ie!e:Jnone: 28!26D.570C Facs,nrie: 281.260.5780

Precision Drilling

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Overview of Computalog

CHAPTER1 Directional Drilling Introduction Directional Drilling Terminolo~­ ~\pplications of Directional Drilling Directional Drilling Limits

CHAPTER2 Methods of Deflecting a Wellbore Bottomhole ~\ssemblies Building ~\ssemblies Dropping ~\ssemblies Holding ~\ssemblies Jetting Special BH.:\'s Stabilization Rotating Blade Type Continue .... Integral Blade Stabilizer \Velded Blade Stabilizers Shrunk on Sleeve Stabilizers Replaceable Slee,·c-Type Stabilizer

Common BfL\ Problems \Xib.ipstock Dm,·nhole :.\Iotors w/ Bent Sub Steerable ~\ssembh·

CHAPTER3 Downhole Mud Motors l\Iotor Selection Components Dump Sub ~\ssembly Power Section Drive _\ssembh· ~\djustable ~\ssembly

Sealed or l\Iud Lubricated Bearin'ith shallow, severe doglegs. These problems are drill pipe fatigue, drill string wear, casing wear, keyseats, torque, drag, and production problems. \\11en drilling directional wells, changes in the dogleg severity should be minimized to prevent problems but it depends on the depth of the dogleg. All changes should be as gradual as possible and still accomplish the objectives.

STEERABLE ASSEMBLY A steerable assemblY. is deflned as a bottomhole assemblY. whose directional behavior can be modified by adjustment of surface controllable drilling parameters including rotary speed and weight on bit. The ability to modify behavior in this way enables the assembly to be steered toward a desired objecti\"e \N'ithout its removal from the wellbore. To some extent, rotary assemblies are steerable if the build m drop tendency is weight sensitive. However, the ability to control a rotar:r assembly is limited especially controlling walk. The most common steerable assembly consists of a PDl\I that incorporates a fLxed or adjustable bent housing on top of the bearing housing below the stator. With the smaller displacement of the bit as compared to using a bent sub, the motor can be safely rotated at RPM's up to 50 depending upon the bend setting and formation. The motor housing may also incorporate an 3mm (1/8") undergauge stabilizer. \\lith the bent housing, the stabilizer is not required but the hold tendency of the assembly in the rotar:· mode is improved. The steerable system operates in two modes; sliding and rotar:· drilling. In the slide mode, the motor acts like a typical motor run. The motor is miented in the desired direction (tool face), and drilling progresses without drill pipe rotation. The change in inclination and or direction is derived from the bit tilt from the

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bent housing and the side force created from the stabilizer or the wall contact \vith the motor. In the rotary drilling mode, the assembly is rotated per normal but at lower ,~alues (30 to SO RPJ\1) and d1e side force is cancelled by this rotary action. In some formations the assembly 'W111 change inclination/ direction even in the rotary mode. Because of d1e bit offset or the side force associated \v'ith a steerable system, d1e assembly 'W111 drill an overgauge hole in the rotary mode. Advances in downhole motor reliabilitY have made the steerable system economical in many applications. Typically, the mean time between failure is in excess of 2000 hours for the motor and excess of 800 hours for the measurement while drilling equipment thereby exceeding d1e life of a tri-cone bit. \\bere feasible, the tri-cone bit has been replaced with a PDC or diamond bit. \\ben properly matched to the formation and motor torque output, a PDC bit can last much longer than a tri-cone bit; however, a PDC bit can not always be used. They are applicable to soft and medium hardness formations with consistent lithology. In areas where formation hardness changes a lot, PDC bits do not perform as well as tri-cone bits. Also the ability or ease of controlling build and turn rates of a PDC van~. considerablY. . In some cases, the penetration rate of a steerable system \\W out perform d1at of a rotary assembly. The majority of the time, it is used in soft formations. As formation hardness increases, rotary assemblies 'vvW drill faster than a steerable system unless special high torque performance motors are used. Harder formations are less sensitive to rotary speed, and bit weight is the predominant drilling parameter. In hard formations, the penetration rate for a motor can be half that of a rotary assembly. In soft to medium hard formations, the penetration rate for a downhole motor has been t'W'ice that of a rotarY. assembh~. . "\s the torque and drag in a directional well increases, the rate of penetration for a steerable system while sliding can be considerably less than while rotating. In some cases it will be half d1e rate seen while rotating. Therefore, it is advantageous to rotate a steerable sntem as much as possible especially when approaching TD. The directional plan can be followed much more closely with a steerable system. Since trips are not required, corrections in the slide mode are made much more frequently. The frequent corrections \NW keep the wellbore closer to the planned path. In the hold section, the directional driller will often rotate for a portion of a connection and slide for the remainder of ilie connection. He must first get a feel for how much ilie assembly is walking and building or dropping while in the rotary mode. Once he gets a feel for iliat then he can determine how much he needs to slide per connection and what ilie tool face orientation must be.

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This does not mean that the dogleg severi0· is very low. It only means that the changes are small and frequent. StuTeys at 20m to 30m inteJTals vvillnot pick up the actual dogleg severi0· in the v\·ell. \X'hereas with rotat·y assemblies and motor corrections, the dogleg severi0· is picked up by the surveys. Frequent motor corrections (short dogleg intervals) will minimize problems associated \\'"i.th keyseats. The doglegs are not long enough for keyseats to form easily. The steerable system should be designed to generate a dogleg sev·eri0· 25 percent greater than that required to accomplish the objectives of the directional plan (a more aggressive bent housing setting). Formation tendencies can cause the dogleg sev·eri0· of a steerable system to change. If it decreases the dogleg severitv generated by the system, then a trip may be require to pick up a more aggressive assembly. However if the assembly is designed to be more aggressiv·e, then the assembly will still be able to produce a dogleg severi0· sufficient to keep the wellbore on course and less slide drilling is required resulting in a higher average ROP. Reducing the dogleg severi0· of a steerable system is not a problem. Alternately sliding and rotating the assembly \\'ill reduce the overall dogleg severitv. The most significant advantage of the steerable system is that a trip does not have to be made in order to make a course correction. \X11en a correction is required, the motor is oriented and drilling continues in the slide mode until the correction is complete. Then drilling in the rotary mode continues until the next correction is required. If a steerable system is not used, a trip would be required to pick up a motor assembly before making the correction. After the correction is made, another trip would be required to pick up the rotary assembly. Another advantage of the steerable system is that it prov'ides the abilitv to hit smaller targets at a reasonable cost. Because a trip is not required to make a course correction, the steerable system can hit a smaller target vv'ith less cost. It's not that a small target can not be hit using rotary assemblies and motor corrections; its that the costs increase significantly as the target gets smaller. Steerable systems are 0-pically used in drilling multi-target directional and horizontal wells. Drilling through a cluster of wells is another good application for a steerable system. Drilling out from under a crowded platform may require building, dropping and turning at various rates over a relatively short distance in order to avoid other wellbores. A steerable system is capable of making all the corrections without tripping. In an emnonment where the daily operating costs are high, the steerable system can result in significant savings. Just because the industry has the capability to hit smaller targets does not mean that the targets should be undulv restricted. The smaller the target, the more expensive it can be to hit. \X'ith a

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steerable system, the cost differential isn't as high as it 'Nould be using rotary assemblies and making motor corrections.

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Chapter

DOWNHOLE MUD MOTORS There are two major types of downhole motors powered by mud flow; 1) the turbine, which is basically a centrifugal or axial pump and 2) the positi\~e displacement mud motor (PDJ\1). The principles of operation are shown in Figure 7.1 and the design of the tool are totally different. Turbines were in wide use a number of years ago and are seeing some increased use lately but the PDM is the main workhorse for directional drilling. Turbine Motor

Positive Displacement Motor

Figure 7-1 Motor Types

Motor Selection Four configurations of drilling motors prm,ide the broad range of bit speeds and torque outputs required satisfying a multitude of drilling applications. These configurations include: High Speed

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Low Torque

Medium Speed

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Medium Torque

Low Speed

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High Torque

Low Speed

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High Torque -Gear Reduced

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The high speed drilling motor utilizes a 1:2 lobe power section to produce high speeds and luw torque outputs. They are popular choices when drilling with a diamond bit, tri-cone bit drilling in soft formations and directional applications where single shot orientations are being used. The medium speed drilling motor typically utilizes a -t-:5 lobe power secnon to produce medium speeds and medium torque outputs. They are commonly used in most conventional directional and horizontal wells, in diamond bit and coring applications, as well as sidetracking. The low speed drilling motor typically utilizes a 7:8 lobe power section to produce low speeds and high torque outputs. They are used in directional and horizontal wells, medium to hard formation drilling, and PDC bit drilling applications. The gear reduced drilling motor combines a patented gear reduction system with a 1:2 lobe high speed po"\ver section. This system reduces the output speed of the 1:2 lobe power section by a factor of three, and increases the output torque by a factor of three. The result is a drilling motor \V"ith similar performance outputs as a low speed drilling motor, but \V"ith some signitlcant benetlts. The 1:2 lobe power section is more efticient at converting hydraulic power to mechanical power than a multi-lobe power section and also maintains more consistent bit speed as weight on bit is applied. This motor can be used in directional and horizontal wells, hard formation drilling, and PDC bit drilling applications. Some other motor selections are also available including a tandem and moditled motor. These ,~ariations are described belo"\v. Tandem Drilling Motor- The drilling motor utilizes two linked power sections for increased torque capacity. :tvloditied Drilling Motor - The bearing section of the drilling motor has been moditled to prm~ide different drilling characteristics (ie. change bit to bend distance, etc.).

Components All drilling motors consist of tlve major assemblies: 1.

Dump Sub Assembly

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Power Section

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Drive Assembb:

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Adjustable Assembly

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5.

Sealed or l\Iud Lubricated Bearing Section.

The gear reduced drilling motor contains an additional section, the gear reducer assembly located within the sealed bearing section. Some other motor manufacturers have bearing sections that are lubricated by the drilling tluid.

Dump Sub Assembly .~s a result of the power section (described below), the drilling motor will seal off

the drill string ID from the annulus. In order to prevent wet trips and pressure problems, a dump sub assembly is utilized. The dump sub assembly is a hydraulically actuated vah'e located at the top of the drilling motor that allm\'S the drill string to till "\vhen running in hole, and drain when tripping out of hole. \\ben the pumps are engaged, the valve automatically closes and directs all drilling tluid tlow through the motor. In the e\'ent that the dump sub assembly is not required, such as in underbalanced drilling using nitrogen gas or air, it's effect can be negated by simply replacing the discharge plugs with blank plugs. This allows the motor to be adjusted as necessary, even in the field. Drilling motors 95 mm (3 3/ 4") and smaller require the dump sub assembly to be replaced with a special blank sub.

Power Section The drilling motor power section is an adaptation of the Moineau type positive displacement hydraulic pump in a reversed application. It essentially converts hydraulic power from the drilling tluid into mechanical power to drive the bit. The po"\ver section is comprised of two components; the stator and the rotor. The stator consists of a steel tube that contains a bonded elastomer insert with a lobed, helical pattern bore through the centre. The rotor is a lobed, helical steel rod. \\ben the rotor is installed into the stator, the combination of the helical shapes and lobes form sealed cavities between the two components. \\ben drilling tluid is forced through the power section, the pressure drop across the ca·vities will cause the rotor to turn inside the stator. This is how the drilling motor is powered. It is the pattern of the lobes and the length of the heli.x that dictate what output characteristics will be developed by the power section. By the nature of the design, the stator always has one more lobe than the rotor. The illustrations in Figure 7-2 show a 1:2 lobe cross-section, a 4:5 lobe cross-section and a 7:8 lobe cross-section. Generally, as the lobe ratio is increased, the speed of rotation is decreased.

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7:l.lL.08E

Figure 7-'2: Cross-sections of the most common power section lobe configurations The second control on power section output characteristics is length. ~A. stage is defined as a full helical rotation of the lobed stator. Therefore, power sections may be classified in stages. A four stage power section contains one more full rotation to the stator elastomer, when compared to a three stage. \\'ith more stages, the power section is capable of greater m-erall press·ure differential, which in turn provides more torque to the rotor. As mentioned above, these two design characteristics can be used to control the output characteristics of any size power section. This allows for the modular design of drilling motors making it possible to simply replace power sections when different output characteristics are required. In addition, the variation of dimensions and materials \Vill allow for specialized drilling conditions. \\'ith increased temperatures, or certain drilling fluids, the stator elastomer will expand and form a tighter seal onto the rotor and create more of an interference fit, which may result in stator elastomer damage. Special stator materials or interference fit can be requested for these conditions.

Drive Assembly Due to the design nature of the power section, there is an eccentric rotation of the rotor inside of the stator. To compensate for this eccentric motion and convert it to a purely concentric rotation drilling motors utilize a high strength jointed drive assembk . The drive assemblY . consists of a drive shaft with a sealed and lubricated drive joint located at each end. The drive joints are designed to 'Wi.thstand the high torque values delivered by the power section while creating minimal stress through the drive assembly components for extended life and increased reliability. The drive assembly also provides a point in the drive line that 'Wi.ll compensate for the bend in the drilling motor required for directional control.

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Adjustable Assembly Most drilling motors today are supplied with a surface adjustable assembh-. The adjustable assembly can be set from zero to three degrees in \'arying incre~ents in the field. Tlus durable design results in "\vide range of potential build rates used in directional, horizontal and re-entry wells. Also, to mininUze the wear to the adjustable components, wear pads are normally located directly abm-e and below the adjustable bend.

Sealed or Mud Lubricated Bearing Section The bearing section contains tl1e radial and thrust bearings and busl-llngs. They transmit the axial and radial loads from the bit to the drill string while providing a drive line that allows the power section to rotate the bit. The bearing section may utilize sealed, oil filled, and pressure compensated or mud lubricated assemblies. \\'ith a sealed assembly the bearings are not subjected to drilling fluid and should provide extended, reliable operation with minimal wear. As no drilling fluid is used to lubricate tl1e drilling motor bearings, all fluid can be directed to the bit for maximized hydraulic efficiency. This provides for improved bottom-hole cleaning, resulting in increased penetration rates and longer bit life. The mud lubricated designs typically use tungsten carbide-coated sleeves to provide the radial support. Usually ..J.% to 10% of the drilling fluid is diverted pass tlus assembly to cool and lubricate tl1e shaft, radial and thrust bearings. The fluid then exits to the annulus directly above tl1e bit/ drive sub.

Gear Reducer Assembly An alternative to the type low speed drilling motor is the gear reduced design. It utilizes a gear reduction assembly \\1.thin the sealed bearing section in combination \"\1.th a 1:2 lobe power section. This patented design reduces the speed of rotation by a factor of three while increasing the torque by the same multiple. The benefit with this design is increased stability in the bit speed for different differential pressures, and improved hydraulic efficiency out of tl1e power section.

Kick Pads Most drilling motors can incorporate wear pads directly above and below the adjustable bend for imprm-ed wear resistance. Eccentric kick pads can also be used on most motors ranging from 121 mm (4 3/4') to 24.5 mm (9 5/8") in size. This kick pad is adjustable to match the low side of the motor to increase build rate capabilities. It will also allow lower adjustable settings for similar build rates, thereby reducing radial stresses applied to the bearing assembly, and permit safer rotation of the motor. They can be installed in the field by screwing them onto specially adapted bearing housings.

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Figure 7-3 General motor component layout

Stabilization Bearing housings are also available with two stabilization styles, integral blade and screw-on. The integral blade style is built directly onto the bearing housing and thus cannot be removed in the field. The screw-on style provides the option of installing a threaded stabilizer sleeve onto the drilling motor on the rig floor in a

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matter of minutes. The drilling motor has a thread on the bottom end that is cm~ered \Vith a thread protector slee\Te when not required. Both of these stvles are optional to a standard bladed bearing housing. .

Drilling Motor Operation In order to get the best performance and optimum life of drilling motors, the following standard procedures should be followed during operation. Slight variations may be required ·with changes in drilling conditions and drilling equipment, but attempts should be made to follow these procedures as closely as possible.

Assembly Procedure & Surface Check Prior to Running in Hole Most motors are shipped from the shop thoroughly inspected and tested, but some initial checks should be completed prior to running in hole. TI1ese surface check procedures should only be used \vith mud drilling systems. To avoid potential bit, motor, and BOP damage, these preliminary checks should be completed \vithout a bit attached. A thread protector should be installed in the bit box whenever moving the motor, but must be removed before flow testing. 1.

The correct lift sub must always be installed and used for moving the tool on or off the rig floor, and for lifting the tool into position for make-up. ~\lso be sure the connection between the lift sub and the drilling motor is tight. To lift the drilling motor to the rig floor, use a tugger line secured around the lift sub. Pick up the drilling motor "vith the elevators and set it into the slips of the rotary table. Install the dog collar/ safety clamps. The lift sub supplied "\vith the drilling motor should only be used for lifting the drilling motor. The capacity of the lift sub is restricted to the weight of the drilling motor and should not be used for any other purpose. Only apply rig tongs on the identified areas of the drilling motor. All connections marked "NO TONGS" of the drilling motor are torqued in the service shop. Further make-up on the rig floor is not necessary, and if attempted may cause damage.

2.

Remove the lift sub and connect the kelly to the drilling motor, remove the safety clamp, and lift the drilling motor out of the slips. Remove the thread protector from the bit box and inspect the threads for damage.

3.

Lower the drilling motor until the dump sub ports are below the rotary table, wt still visible. CAUTION: The dump sub valve "",j_J} remain open until there is enough fluid pressure to close it. Therefore, the drilling

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motor should be lowered until the potts are below the rotary table. This "\veill prevent the initial flow of drilling fluid from spraying on the rig floor. -1-.

Slowly stan the pumps and ensure drilling fluid is fluwing out of the dump sub potts. Increase the flow tate until the dump sub potts close, and drilling t1uid stops flowing out. Make note of the circulation tate and standpipe pressure. CACTION: Do not exceed the maximum recommended flow tate for this test.

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Lift the drilling motor until the bit box becomes "\"isible. It should be rotating at a slow, constant speed. Listen to the bearing section of the drilling motor for excessive beating noise, especially if the tool has been used pte\"iously \vithout being sen"iced.

6.

Before stopping the pumps, the drilling motor should be lowered belo"\\· the rotary table. Ensure that drilling fluid flows out of the dump sub potts after shutting down the pumps. It is possible that the dump sub valve remains closed after this test due to a pressure lock If this occurs, no drilling fluid will flow out of the potts. To remove the pressure lock, bleed off some stand pipe pressure and the valve 'Weill open. The surface check should be as short as possible; since it is merely to ensure that the drilling motor is rotating.

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After this surface check, the bit should be attached to the motor using a bit-breaker, while holding the bit box stationary with a rotary tong. Be sure to a\·oid contacting the end cap directly above the bit box with the tong dies. It is recommended that you never hold the bit box stationary and rotate the drilling motor countet-cloch.\vise, or hold the drilling motor stationary and rotate the bit box clockwise. This could possibly cause the internal drilling motor connections to back off and damage it. Although rotating in the opposite direction 'Weill result in drilling fluid to be pushed out the top end, the internal connections will not be at risk of disconnecting. Get wet or damage motor.

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If the drilling motor has been used prev-iously, an overall inspection should be completed. Inspect for seal integrity by cleaning the area above the bit box and \"isually checking for lubricating oil leakage or seal extrusion. General ·v-isual inspection of tl1e entire drilling motor should be carried out to check for missing oil plugs, housing damage, or loose connections.

9.

Set tl1e adjustable assembly to the desired bend. The instructions for this procedure depend upon the motor manufacturer and should be adhered to. Ensure the rig tongs can generate the requited make-up torque the motor.

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10.

If a float sub is used, it should be placed immediately above the drilling motor.

Tripping In Hole Generally, a drill string \vith a drilling motor can be run into the hole like a standard bottom hole assembly. The drilling motor is rugged, but care should be taken to control travel speed while tripping into the hole. The drill string should be tripped \\-i.th the blocks unlocked and special care must be taken when passing the B.O.P., casing shoe, liner hanger, bridges and nearing bottom. Tight spots should be traversed by starting the pumps and slowly reaming the drilling motor through. \\ben reaming, the drill string should be periodically rotated to prevent sidetracking. Great care should be taken during these operations. \\ben tripping to extreme depths, or when hole temperatures are high, periodic stops are recommended to break circulation. This prevents bit plugging and aids in cooling the drilling motor, prewnting high temperature damage. Fluid should not be circulated through a drilling motor inside casing if a PDC or diamond bit is being used, as this may damage the bit cutters. If a dump sub assembly is not used and the pipe is not being filled while tripping in, the back pressure on the power section \\-ill cause the rotor to turn in reverse. This could cause internal connections of the drilling motor to unscrew. Stop and break circulation before putting drilling motor on-bottom. Failure to do so could plug jets and/ or damage the drilling motor.

Drilling After the assembly has been tripped to the bottom of the hole, drilling motors should be operated in the following manner: 1.

\'\'ith the bit 1-2 meters (3-6 feet) off bottom, start the pumps and slowly increase the flow rate to that desired for drilling. Do not exceed the maximum rated flow rate for the drilling motor.

2.

Make a note of the flow rate and the total pump pressure. Note that the pressure may exceed the calculated off bottom pressure due to some side load effects between the bit and the hole diameter.

3.

After a short cleaning interval, lower the bit carefully to bottom and slowly increase the weight. Torque can be affected by a dirty, uncirculated hole and the hole should be adequately cleaned prior to orienting the tool. Fill maybe cleaned out of the wellbore by slowly rotating the drilling motor or

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by staging the drilling motor full circle 30° to 4-So at a time. This prevents ledge buildup and side tracking.

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Orient the drill string as desired and slowly apply further weight onto the bit. Pump pressure v.rill rise as the weight on bit is increased. Record the change in system pressure between the off bottom and on bottom \~alues. This v.rill be the differential pressure. Try to drill with steady pump pressure by keeping a steady flow rate and constant weight on bit. Adding weight on bit \\W cause both the differential pressure and torque to increase. Similarly, reducing weight on bit will reduce both the differential pressure and the torque. Therefore, the rig pressure gauge enables the operator to monitor how the drilling motor is performing, as well as a weight on bit indicator. Applying excessive weight on bit may cause damage to the on-bottom thrust bearings. SimilarlY, applving excessive tension while stuck may cause damage to the off-bottom thrust bearings. Refer to the manufacturer specifications for the recommended maximum loads for these conditions. Optimum differential pressure can be determined by monitoring motor performance, penetration rate, and drilling requirements. Also, maintaining a constant weight on bit and differential pressure assists in controlling orientation of the drill string.

Reactive Torque Drilling motors drive the bit \vith a right-hand (clockwise) rotation. ~\s weight is added to the bit, reactive torque acting on the drilling motor housing is dewloped. This left-hand (counter-clockwise) torque is transferred to the drill string and may cause the joints above the motor to tighten. Reactions of this type increase with larger weight on bit values and reach a maximum when the motor stalls. This reactive torque also affects the orientation of the motor when it is used in directional drilling applications. Therefore, this reactive torque must be taken into account when orienting the drilling motor from the surface in the desired direction. As a rule-of-thumb 4 1 'z" drill pipe will turn 10° for every 300m (1,000'). Determining the amount of torque generated by the motor and using drill pipe twist tables can also produce a rough determination of the torsional angle of the drill string. By measuring the on-bottom and off-bottom pressure, the differential pressure can be determined. \X'ith this value use the torque performance charts for the motor to determine the approximate downhole torque generated. "Ctilizing the follO\ving drill string twist table -v.w estimate the amount of reactive torque.

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3 1/z" - 13.30 lb I ft drill pipe 19 degrees per 100 N.m torque per 1000m of hole 8 112 degrees per 100 ft -lb torque per 1000 ft of hole 3 11z"- 15.50 lblft drill pipe 17 degrees per 100 N .m torque per 1OOOm of hole 7 11z degrees per 100 ft-lb torque per 1000 ft of hole 4

11 2"-

5"

16.60 lblft drill pipe 7 Lz degrees per 100 N.m torque per 1000m of hole 3 113 degrees per 100 ft-lb torque per 1000 ft of hole 19.50 lb I ft drill pipe 6 degrees per 100 N .m torque per 1OOOm of hole 2 518 degrees per 100 ft-lb torque per 1000 ft of hole

Example: 159mm high speed motor with an applied differential pressure of ::2000 KPa produces a torque of 720 N-m. \\'e are drilling at a depth of 800m with 4 1/z" drill pipe. Potential reactive torque is 800 I 1000 x 720 I 100 x 7 = 40 degrees

Critical Rotary Speed I\fotor sections are a\'ailable in a number of configurations. These different designs are identified by the number of lobes on the rotor and ca,'ities in the stator. For example a 415 power section has 4 lobes and 5 cavities. \\'ith even· rotation made by the rotor, there are eccentric motions about the radius of the rotor equal to the number of lobes. So a -+15 power section would go through 4 eccentric movements for every rotation. In all multi-lobed tools, regardless of size or configuration, the critical tolerance for this eccentric mo\'ement is 1000 cycles per nunute. Exceeding this critical tolerance sets up three degenerative cycles in the tool: •

The high oscillation factor combined '.Vi.th the inherent friction of the rotor contacting the stator results in excessive heat generation in the stator molding. Oscillations above 1000 cycles per minute may result in temperatures sufficient to cause hysteretic failure of the stator molding (elastomer doesn't return to original shape).

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Vibration frequencies are introduced by the high oscillation rates that can contribute to mechanical failures in motor components other than the rotor and stator. It is not known if these vibrations are harmonic or random however, it is logical to assume that some degree of resonance would be present in the frequency.

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The centrifugal force of the rotor in an "over-speed" condition combined '..Vith the diminished compressive strength of a stator in hysteretic failure, accentuate the eccentric motion (run out) of the rotor. The result is an expontenial increase in the degenerative effects of the condition.

Drilling Motor Stall Stalling usually occurs when the application of excessive weight on bit or hole sloughing stops the bit from rotating and the power section of the drilling motor is not capable of prm-iding enough torque to power through. This is indicated by a sudden sharp increase in pump pressure. This pressure increase is de,-eloped because the rotor is no longer able to rotate inside the stator, forming a long seal between the two. If circulation is continued, the drilling fluid forces it's way through the power section by deflecting the stator rubber. Drilling fluid ·will still circulate through the motor, but the bit '..VW not tum. Operating in this state ,,;n erode and possibly chunk the stator in a very short period of time, resulting in extensiw damage. It is very important to avoid this operating condition. \\11en stalling occurs, corrective action must be taken inlmediately. Any rotary application should be stopped and built up drill string torque released. Then the weight on bit can be reduced allowing the drill bit to come loose and the drilling motor to turn freely. If the pump pressure is still high, the pumps should then be turned off. Once again, failure to do this '..VW result in the stator eroding until the drilling motor is inoperable. Other conditions can be occurring downhole that indicate the motor is stalling. On underbalanced wells when the motor is being supplied with too low a combined equivalent flow rate '..VW not drill (see later discussion on two-phase flow tests). Under gauge bits or a badly worn heel row of cutters on the bit can also make the motor stall.

Bit Conditions The bit speeds developed '..vhen drilling with a drilling motor are normally higher than in conventional rotary drilling. This application tends to accelerate bit wear. \\ben drilling with a drilling motor and simultaneously rotating the drill string, it is important to avoid locking up the bit and over running the drilling motor '..vith the rotary table. A locked bit will impart a sudden torque increase in the drilling motor which can be detected by a sudden, sharp increase in standpipe pressure. Small pressure fluctuations can also indicate the onset of bit failure.

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Rotating the Drilling Motor For directional control, we often rotate a drilling motor which has the adjustable assembly set for a deviation angle. It has been found that rotating the drilling motor set at bends greater than 1.8 degrees may fatigue the housings of the drilling motor to a point where a fatigue crack is initiated, and fracture occurs. Additionally, rotation of motors with settings greater than 1.83 degrees place high radial stresses on the bearing section which may initiate premature failure. :tYiost motor manufacturers have a policy that drilling motors set at greater than 1.83 degrees not be rotated. The extent of the damage is very dependent upon the drilling conditions and formations being drilled. Although fractures from fatigue due to rotating over 1.83 degrees are a relatively rare occurrence, a risk is still being taken when it is done. The operator of the drilling motor must be aware of this risk. It is also recommended that the speed of rotation not exceed SO RPM. If this is exceede._:_ excessive cyclic loads would occur to the drilling motor housings and possibly causing pre-mature fatigue problems. ,~alue

Tripping Out Prior to tripping out when drilling with conventional mud, it is recommended that the fluid be circulated for at least one "bottoms-up' time to ensure that the wellbore has been cleaned thoroughly. The tripping out procedures for a drilling motor is basically the same as those for tripping in. Taking care when pulling the drilling motor through tight spots, liner hangers, casing, casing shoes, and the B.O.P. is necessary to minimize possible damage to both the drilling motor and the wellhead components. Rotating may also be done to assist with the removal of the drill string. The dump sub valve vvill allow the drill string to be emptied automatically when tripping. ~~though

the drill string will drain when tripping out, the drilling motor itself may not. Once the drilling motor is at surface, rotating the bit box in a counterclockwise direction vvill naturally drain the drilling motor through the top. This is recommended before laying down the motor since aggressive drilling fluids can deteriorate the elastomer stator and seals. \\'hen possibly, fresh water should also be flushed through to ensure thorough cleaning of the drilling motor. Also, clean the bit box area with clean water and install a thread protector into the box connection. Rotating the bit box in a clockwise direction vvill naturally drain the drilling motor through the bottom, but one of the internal connections could break and unscrew. For this reason, it is not recommended to rotate it in this manner.

53

Surface Checks After Running in Hole Before laying down a drilling motor, it should be inspected in the ev:ent that it is required again before servicing. Listen for indications of internal damage when draining the drilling motor. Inspect the seal area between the bit box and the bearing section for lubricating oil leakage, and check the entire drilling motor for loose or missing pressure plugs. If there are any concerns \vith the drilling motor, it should be laid down for sen'icing.

Drilling Fluids Most drilling motors are designed to operate effectively \vith practically all types of drilling fluids. In fact, the stator or pO\ver-section of most PD.I'v1's are supplied by the same one or two manufacturers \vith the same general elastomer type. Successful runs hav:e been achieved with fresh or salt water, oil based fluids, fluids \vith additi\'es for \'iscosity control or lost circulation, and \Vith nitrogen gas. However, some consideration should be taken when selecting a drilling fluid, as elastomer components of the drilling motor are susceptible to pre-mature wear when exposed to certain fluids especially under higher temperatures. Hydrocarbon based drilling fluids can be v:ery harmful to elastomers. A measure of this aggressiveness is called the Aniline Point. The Aniline Point is the temperature at which equal amounts of the hydrocarbon and aniline become miscible. This temperature is an indication of the percent of light ends (aromatics) present in the hydrocarbon. It is recommended that the aniline point of any drilling fluid not be lower than 70 to 94.5° C (158 to 200° F), depending upon stator manufacturer. The lower the aniline point the higher the percentage of elastomer damaging "high-ends" in the hydrocarbon fluid. Also, the operating temperature of the drilling fluid should be lower than the aniline point. Operating outside these parameters tends to excessively swell elastomers and cause premature wear, thus reducing the performance of the motor. In cases where hv:drocarbon based fluids are used it is recommended that stators material or designs that account for the elastomer swelling be used (HSN or changed interference of stator/rotor. Drilling fluids with high chloride content can cause significant damage to internal components (chrome plated rotors). \\ben these components become damaged, the drilling motor's performance is dramatically reduced. Lost circulation materials can be used safely with drilling motors but care must be taken to add the material slowly to avoid plugging the system. (Good rule of thumb is no more than 2.5 lbs/barrel). If coarse lost circulation material is required a circulating sub should be installed above the motor assembly to by-pass the motor.

54

The percentage of solids should be kept to a nurumwn. Large amounts of abrasive solids in the drilling fluid will dramatically increase the wear on a stator. It is recommended that the sand content be kept below 2% for an acceptable operational life. A solids content greater than 5°'o will shorten rotor and stator life considerablY. For the above reasons, it is extremely important to flush the drilling motor '.vith fresh water before laying it dmm, especially when working "'~th the types of drilling fluids described abo,·e. Failure to do so "'~ allow the drilling fluid to further seriously deteriorate components to the drilling motor long after it has been operated. The solids can also settle out in tl1e motor and in the worse case lock the motor up.

Temperature Limits The temperature limits of drilling motors again depend on the effect of different fluids and temperatures on the components made of elastomers. Generally, standard drilling motors are rated for temperatures up to 105° C (219° F). At temperatures abm·e this, the performance characteristics of elastomers are changed, resulting in reduced life expectancy. \\'hen exposed to higher temperatures, the elastomers swell, creating more interference than desired, wearing the parts out prematurely. The strength of the elastomers is also affected. \\'hen drilling in wells Mth temperatures greater than 121 o C (250° F) it is important to maintain circulation to minimize the temperature the stator liner is subjected to. To compensate for these elastomer changes, special materials and special sizes of components are used. This results in drilling motors that are specifically assembled for high temperatures. These special order drilling motors may be operated in temperatures up to 150° C (300° F) and higher. The rubber in the stator is specially selected for more clearance at higher temperatures to minimize interference. Therefore, at lower temperatures, the stator elastomer "'~ not seal adequately on the rotor and fluid bypass "'~ occur. Therefore, it is important that the drilling motor be used in the conditions it is designed for in order to operate as required.

Hydraulics The use of a PDM in the drill string changes the hydraulic calculations and should be considered. Various factors have to be taken into account. These are:

1. Range of flow rates allowable: Each size and type of PDM is designed to take a certain range of volwnes of fluid.

55

2. No-load Pressure Loss: \\ben mud is pumped through a mud motor which is turning freely off-bottom (i.e. doing no \Vork) a certain pressure loss is needed to overcome the rotor/stator friction forces and cause the motor to turn. This pressure loss and motor RPM are proportional to flow rate. Their \-alues are known for each size and type of PDJ\L The no-load pressure loss is usually no greater than 100 psi. 3. Pressure Drop across the Motor: As the bit touches bottom and effective \\'OB is applied, pump pressure increases. This increase in pressure is normally called the motor differential pressure. l\lotor torque increases in direct proportion to the increase in differential pressure. This differential pressure is required to pump a given volume of mud through the motor to perform useful work. For a multilobe motor, it can be 500 psi or even more.

-t Stall-out Pressure: There is a maximwn recommended value of motor differential pressure. ~\t this point, the optimum torque is produced by the motor. If the effective \\'OB is increased beyond this point, pump pressure increases further. The pressure across the motor increases to a point \Vhere the lining of the stator is deformed. The rotor/stator seal is broken and the mud flows straight through ·without turning the bit (blow-by or slippage). The pump pressure reading jumps sharply and does not nry as additional \\.OB is applied. This is known as stall-out condition. Studies have shown that the power output curve is a parabola and not a smooth upward curn, as originally thought. If the PDM is operated at 50%)-60° o of the maximum allowable motor differential pressure, the same performance should be achie\-ed as when operating at 90° o of differential. The former situation is much better howe\-er, there is a much larger 'cushion' available before stall-out. This should result in significantly longer motor life. 1

The greater the wear on the motor bearings, the easier it is to stall-out the motor. It is useful to deliberately stall out the PDM briefly on reaching bottom. It tells the directional driller what the stall-out pressure is. He may \Vant to operate the motor at about 50% of stall-out differential pressure. In any case, he must stay \V'ithin the PDM design specifications. It is obvious that, if the pump pressure while drilling normally \V'ith a mud motor is close to the rig's maximum, stalling of the PDM may lead to tripping of the 'pop-off valve'. This should be taken into account in designing the hydraulics program. Rotor Nozzle: Most multi-lobe motors have a hollow rotor. This can be blanked off or jetted with a jet nozzle. \\'hen the standard performance range for the motor matches the drilling requirements, a blanking plug is normally fitted.

56

The selection of the rotor nozzle is critical. Excessive bypass will lead to a substantial drop in motor performance and, consequently, drilling efficiency. If a rotor nozzle is used at lower flow rates, the power of the motor be greatly reduced.

'"ill

From the above, it is clear that careful planning of the PDM hydraulics program is required.

57

171 mm I

MOTOR SPEClF!CAT!ONS

Computalog CommanderTM I 1:2 Lobe, 4.0 Stage

500 gorn I,A AX itT: UfT!

DIMENSIONAL DATA

Ma>-irr:urn

P{~~Nef'

1500

PERFORMANCE CHARTS

mm '78 rnm

6750 :n 7.000

rnm 270 mrn

;:oo io: UlTIMATE lOAD fACTORS S. 000 of\ 40,000 rJi\ 35.000

480.000 ID' 202,000 Ia'

ESTIMATED BUILD RATES DEGREES .jOfv!

I

FT.

liELLBORE DlAMETEn

E

K l

2.97

M

3

Ad 1us:ablf i3.600 NVhich occur when the inclinometer is exposed to the shocks and vibrations of the drilling envrronment.

Applications of Magnetics and Gravity In the .M\\D sensor package, two sets of sensors are used. One set (magnetometers) uses an A'YZ system to measure orientation with respect to the earth's magnetic field (H" H,, HJ The other set (accelerometers) uses an Ar or ArZ system to measure orientation with respect to the earth's gra,·itational field

(G,, G,, GJ From the magnetic sensors we can learn inclination, azimuth, and tool face angles. From the gra\'i.ty sensors we can learn inclination and tool face angle .

.Magnetic T oolface, l\1TF For hole inclinations of 0 to 5 degrees use magnetics to determine hole direction. i.e. N 65°£ i.e. MTF

= Magnetic "\zimuth + /- Declination + T oolface Offset (N) (0)

(\\')

(90)

(270)

(180) (S)

104

(E)

Gravity Toolface, GTF For hole :inclinations of 5+ degrees use gravity to determine the hole direction. i.e. 65° or 65 R i.e.GTF= Tool Highside Angle +/-Declination + Toolface Offset Highs ide (0)

Left (90)

Right (90)

(180) Down

105

NEGATIVE PULSE OFFSET TOOL FACE OFFSET TOOL FACE (OTF) SHEET This sheet is possibly the most important form that must be filled out correctly. All other work and activity performed by the M\'CD Operator means naught if the well must be plugged back with cement because of an incorrect OTF calculation (or the correct OTF not being entered into the TL\X' 2.1.2 software). Ensure that the OTF calculation is correct, entered into TLW 2.12 correctly and verified by the Directional Driller. The procedure for measuring the OTF is as follows: 1. 1\Ieasure in a clockwise direction the distance from the l\1\X.D high side scribe to the motor high side scribe. Record this length into the OTF work sheet as the OTF distance. In the following example, this value is 3.51 mm. " l\1easure the circumference of the tubular at the same location ·where the OTF distance is being measured. Record this length into the OTF work sheet as the Circumference of Collar. 3. Calculate the OTF angle using the following formula:

OTF Angle=

OTF Distance x 360 Collar Cirumference

From the abo,·e example, if the collar circumference 1s 500 mm,

OTF Angle= (351/500) x 360 0.702 X 360 252.72°

= =

A sample form is as follows:

106

COMPUTALOG NEGATIVE PULSE OFFSET TOOL FACE (O.T.F. MEASUREMENT) Well Name:

Enter in the Well Name here

Date: Enter in date OTF taken

Time: Enter in time OTF taken

LSD:

Enter in the LSD here

Job#:

Enter in the MWD job number here

Run #: Enter in the run number

TOP VIEW OF MWD

MOTOR SCRIBE (HIGH SIDE) O.T.F D1st:mce (.\nchor Bolts

to

Collar Scribe):

\

351 mm

Circumference of Coll:Jr:

500 mm

O.T.F. "·\ngle (Disunce /Circumference) x 360:

~5~ ..... ~

O.T.F .\ngie entered into Computer as:

252.-2 degrees

degrees

O.T.F. Distance measured b,-,

Both ;\1\\D Operator l\iames

O.T.F. Calculated b,-,

Both 1\I\\D Operator ]\i ames

O.T.F Entered into computer b'c

Both 1\I\\D Operator Names Directional Driller(s) Name(s)

O.T.F. 1\Ieasurement and calculation \\"itnessed b,-:

107

NEGATIVE PULSE OFFSET TOOL FACE

Iool Face Offset J22 80

Magnetic Declination

!;:::::::::=::::~

Mag. -> Grav. If Inc >

3.00 :::=:::::=::::~

Ll=_~.s_o_ __

Grav. ->Mag. If Inc< ···· Driller Displays

P" Deyelco

w

Small LED

r.

M\JVD

· · Operator Display·

r

OFF

r

ROP

CCB Formats

IJ

Basic

BasicCalc Ba::;icCalc\/L Elasic'v'L Gamma Cancel

108

POSITIYE PULSE

TOOLF~\CE

OFFSET

INTERNAL TOOL FACE OFFSET (TFO) SHEET Note: For the positive pulse M\v'D, the OTF is zero. Ensure that a zero OTF has been entered into TL\\' 2.12. The positive Tool Face Offset (TFO) sheet entries are as follows: 1. Positive Pulse Pulser Set to High Side / Directional Driller: Enter the names of the "tvf\\D Operator and Directional Driller respectively. 2.Positive Pulse T.F.O. from PROGTJ\1: Enter the T.F.O. value reported from the high side tool face calibration from TLW 2.12. TFO internal toolface offset :~Tl\11 2.12- MWD for Windows [Basic)

8 8 1 1 :::

!lliiEJ

Rx pump?; Tx pump 0 .OOOOOOE+OO; F:x tfo?; Tx tfo· 2 289000E+02; Rx RDFCBSEQ,

8 Rx RDFCBSEQ;

:TLWstatus Messages Toolface Calibration is Complete. Measured gravitational tooliace after calibration 228.9 degrees Tooliace Calibration is Complete Measured gr Grav. If Inc >

{3.00

Grav. -> Mag. If Inc